The reliable operation of the electric power system requires maintaining a balance between the total supply (i.e., generation and imports) and the total demand (i.e., load and exports) at any given time. Under guidelines established by the North American Electric Reliability Corporation (NERC) that regulate the reliability of power system operations, the North American power grid is divided into many adjacent balancing areas, each responsible for maintaining the balance between the supply and demand in their respective region. To achieve the balance in a most economic fashion, the electric utility industry has historically utilized load forecasting and economic dispatch optimization systems to optimize the scheduling of generation resources in such a way as to minimize the cost for the production of electrical energy sufficient to meet the forecasted demand, while taking into account capacity reserved for contingency reserves and regulation (ancillary services), and then dispatch these resources in real time to maintain the supply and demand balance and meet the energy demand of the utilities' consumers at least cost. These economic dispatch optimization systems typically consider the generation from facilities under the control of a single Balancing Area, for example energy generating plants fueled by natural gas, coal, nuclear fuel, water (hydro), oil, and refuse, as well as energy available for purchase from electricity suppliers on an energy market, as an import. In order to match forecasted load and meet real-time electricity demand, entities utilizing economic dispatch optimization systems typically increase or decrease generation from particular generation units. The environmental regulations and consumer sentiment of the recent years have resulted in a rapidly expanding portfolio of renewable energy resources in many regions. The renewable generation resources such as, solar and wind power facilities, are generally non-dispatchable and due to their dependence on the amount of pertinent natural resources (e.g., sunshine, wind, etc.) have variable generation patterns, and thus they are referred to as Variable Energy Resources (VER). Nearly all utility companies have now established a trend to incorporate electrical generation from VERs into their generation portfolio. The real time availability as well as accurate long term forecast of natural resources, such as sunlight (unblocked by cloud cover) and wind, remain unpredictable to an absolute degree; although some short term forecasting modeling for cloud cover and wind speed is beginning to yield more accurate predictions on such resource availability. If a stray cloud shields a solar panel array from the sun, there is a near instant impact to the generating capacity output of a solar generation resource, which an electrical utility will have to compensate for through acquiring additional generation from another source. If that same stray cloud then moves on a few short minutes later, the generating output is then ramped back up to a higher capacity. Again, the Balancing Area must readjust generation resources to match the real-time electric demand through its economic dispatch optimization system or other method. Purchase of additional electrical energy from a market, especially during an emergency or on short-notice basis, for balancing periodic generation fluctuations can be costly with such incurred costs passed on to the electricity consumer. Moreover, adjusting the generating output of other traditional generation resources, most notably coal fire generation plants, on an intra-hour basis for short periods of time to mitigate fluctuations to generation output is also costly, if even possible given the physical ramping constraints associated with many such generation facilities.
Use of Demand Response
The use of demand response (DR) to reduce electrical energy demand is well known to electrical utilities. Electric utilities have encouraged consumers to enroll their electrical assets, such as, but not necessarily limited to water heaters, air conditioners and pool pumps, into demand response programs, permitting the electrical utility to cycle or even turn off the enrolled asset to shed load during peak consumption periods (or as otherwise contractually agreed upon). Programs were established to include groups of like assets across a generally shared locality.
Traditionally, electrical utilities have initiated demand response events under emergency conditions without an accurate prediction of available DR. An electrical utility would initiate a DR event to cycle, turn off or otherwise reduce the electrical energy demand of ideally all assets enrolled in a particular program. In practice, an asset may be unresponsive to a DR event initiation signal or may never receive the signal at all. Moreover, asset owners may have the contractual ability to opt-out of certain DR events. The electrical demand of enrolled assets may change based on a variety of factors, including by not limited to external or ambient meteorological conditions (e.g., temperature and humidity), the condition and age of the asset, the time of day or the day type (e.g., work day, weekend, etc.), contractual parameters, and recent history of asset dispatch. Electric utilities have thus far not utilized DR to provide flexible reserves and load following capabilities needed to mitigate variable generation. In fact, utilities generally rely on expensive regulation to absorb the fluctuations of VER, and on Contingency Reserves to mitigate sudden large changes in VER output. The use of load following and ramping products to mitigate variable generation is emerging but is generally limited to provision of these services from dispatchable generation resources. Using DR for provision of such products has been a missing gap in this regard.
Electrical utilities are also unable to accurately predict and account for the amount of available load reduction capacity as well as ramp time for a DR event to begin to be realized. The amount of available load reduction is a function of operating status of the participating assets, ambient conditions and other factors that may not be under control of the electric utility. The initiation of DR events necessarily requires communication of control commands from a dispatch point to all assets participating in the designated DR program. In practice, such communication has historically been accomplished through utilization of many methods such as one-way radio signals, power line carriers, and telephone notifications. More recently, the energy industry has begun to incorporate additional communication methods and protocols for communicating DR events along with corresponding device telemetry, including but not limited to incorporating Wi-Fi, cellular, and various internet methods. Previous one-way networks were more costly and have lower levels of performance. Regardless of the communication method used, electrical utilities also have been unable to accurately and effectively predict and account for the amount of time every individual asset enrolled within a DR program requires for receiving and then responding to a DR event initiation signal. Without such accurate available capacity and ramping information, the real-time utilization of DR as a dependable source of flexible reserve remains infeasible for electrical utilities.
Moreover, electrical consumers have also begun to incorporate additional distributed energy resources (DERs), such as but not necessarily limited to solar panels, backup generation, electric cars, electric battery storage, thermal storage units, among others, in order to reduce their electricity bill or make better use of electric supply. Although the physical characteristics and capacities of many DERs are well known and predictable with incorporation of various real time factors, such as ambient temperature, the accurate modeling of power output and aggregation of multiple DERs is lacking in accuracy and reliability. The power output of DERs must likewise be more precisely modeled and predicted before they can become a dependable flexible reserve source.
Also absent from electrical utilities capability has been the ability to accurately model the effective duration of use of any particular DER. The electrical power output of a DER can be affected by any number of factors, including but not limited to type of unit, wear on the unit or its components, ambient temperature and light, and fuel resource availability or quality. Thus electrical utilities have been unable to dependably utilize DERs for accurate periods of time to mitigate the effects of periodic generation output fluctuations.
Thus, while generally beneficial for the utility to shed a portion of load during periods of peak demand by utilizing DR or incorporating additional generation from DERs, without more dependable and accurate prediction of load shed, anticipation of ramp period, and modeling of effective generation duration, electric utilities have been unable to fully and precisely incorporate DR and DER assets as operating and flexible reserve generation resources in order to mitigate the periodic fluctuations in generation output inherent with the utilization of VERs to balance generation with load demand in real time.